1. Field of the Invention
The present invention relates to formation fluid analysis and, more particularly, to enhanced systems and method of chromatographic analysis of downhole fluids, for example, wellbore fluids, treatment fluids, formation fluids, and drilling muds, utilizing an initial characterization of a property of the fluid prior to further analysis.
2. Description of Related Art
Chromatographic analysis is a technique that is generally used to characterize subsurface produced hydrocarbons in surface based facilities. It provide high-resolution compositional analysis to long chain hydrocarbon compounds including, for example, C36+ or higher. The techniques can be used for equation of state tuning and subsequent compositional modeling of fluids in reservoirs to facilitate or provide reservoir production strategy and planning and design of surface based production facilities.
In surface-based laboratories, typically, the formation hydrocarbon sample is flashed to ambient conditions to separate dissolved gas and liquid hydrocarbon phases. Any water that may be present in the collected liquid hydrocarbon (oil) phase, is separated. Not only can an oil-water mixed injection interfere in quantitative hydrocarbon analysis, but exposure to water can also cause the stationary phase in the chromatography column to degrade rapidly. Standard analytical protocols that include column type and configurations, temperature programs, carrier gas flow rates and pressures, injector and detector temperatures are used for characterization. One or more chromatographic systems and protocols may be used for analysis of the gas and liquid hydrocarbon phase fractions to maximize resolution and accuracy. The typical analysis time of such standardized techniques is in the range of several minutes to an hour.
To access a formation fluid, a formation tester tool with a sampling probe, pump module and a flow line is commonly used. Typically, a sampling probe contacts the formation and a pump is used to withdraw fluid from the formation into a flow line that may contain one or more sensor trains for in situ analysis. Subsequent to that, the fluid may either be disposed into the wellbore or collected in sample bottles for further surface based analysis. The fluid may be single phase or a multiphase mixture of water and gas/liquid hydrocarbons. The initial fluid that is withdrawn into the tool is generally highly contaminated by drilling mud filtrate. This filtrate can be either water-based (immiscible with formation hydrocarbon) or oil-based (miscible with formation hydrocarbon). With continued pumping over time, the contamination drops and the fluid becomes more representative of the true formation fluid.
Pilkington, in U.S. Pat. No. 4,739,654, discloses a method and apparatus for downhole chromatography of single phase flows using a chromatographic system. In the art to Pilkington a resistivity sensor is used in identifying hydrocarbon samples which are not highly contaminated by oil based mud filtrate. Pilkington fails, however, to recite the use of alternative sensors, such as optical sensors, for tracking oil based mud contamination. Additionally, Pilkington fails to address the differentiation between formation water (or a water based mud filtrate) and oil.
If only a chromatographic analytical system is deployed in a downhole environment, the sampling would be blind, with no a priori knowledge of fluid type, e.g., water, gas, and/or liquid hydrocarbon or contamination. Sampling and injection of water into the chromatographic system should be avoided because it is not relevant for hydrocarbon pressure-volume-temperature (PVT) characterization. Water exposure may also cause rapid column stationary phase degradation and/or interference in the quantitative hydrocarbon analysis. Yet another problem with blind sampling is when the hydrocarbon fluid is a mixture of gas and liquid phase, as then it is difficult to sample both phases in representative fractions to get the accurate quantification. To maintain the integrity of the analysis, one would prefer to sample the two phases separately by single-phase injections and get their compositions independently.
Furthermore, it is important to know the percentage contamination, especially when the sample contains miscible oil-based mud filtrate, as high contamination drastically alters the properties of the formation fluid and hence the compositional analysis of such a sample has no value. Acceptable contamination levels in formation fluid samples are of the order of 5% or less for oil-based mud filtrates. With water-based mud filtrates, segregation of the hydrocarbon is important prior to analysis. It is thus advantageous that fluid property characterization and chromatography analysis be done only when contamination levels are below acceptable levels in order for the results to be used for equation of state (EOS) tuning and estimating fluid properties. While chromatography is generally used to estimate contamination in the surface laboratories, repeat sampling over long pumping times to track contamination by chromatography under downhole conditions is not efficient. Not only does it increase consumption of finite resources on the downhole tool, such as carrier gas, it can also cause degradation of column performance. Most columns are reconditioned after a certain number of injections. If more efficient methods are available for contamination tracking, it is advantageous to use chromatography only for sample analysis.
A wellbore typically intersects several formation layers filled with various types of fluid ranging from dry gas to heavy oil. Thus the downhole tool should preferably be able to analyze various kinds of fluids in a single logging run. Without any a priori knowledge of the hydrocarbon sample type, one would have to go with a standard protocol for example, irrespective of whether it is dry gas, with components predominantly to C7 or a black oil, with components all the way to C36 and higher. Thus there is no possibility of tuning and optimizing it for the sample type to improve resolution and accuracy. This could also result in unnecessarily longer analysis times. Long wait times at an analysis station not only translates to higher costs related with rig time but also increases the risk of tool sticking in the wellbore. Longer analysis times would also mean increasing the consumables such as carrier gas, which is an important consideration in a downhole environment, as only limited supplies exist.
It is an aspect of the present invention to address these deficiencies in the prior art.